Apparatus and Method of Manufacture for a Mechanical Radial Drilling Cutting Head

ABSTRACT

A cutting head apparatus for mechanical radial drilling that includes one or more cutting inserts and at least one fluid passage way for the flow of drilling fluid through the cutting head.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present filing claims priority to provisional patent application 62/285,419 filed on Oct. 29, 2015.

FIELD

The present disclosure generally relates to drilling wellbores into a subterranean formation and more particularly to short radius lateral drilling. This disclosure has application to oil, gas, water and geothermal wells. More specifically, this disclosure discusses a novel cutting-head for radial drilling of hard earthen material and methods for manufacturing this apparatus.

BACKGROUND

Natural resources such as oil and gas located in a subterranean formation can be recovered by drilling a wellbore down to the subterranean formation, typically while circulating a drilling fluid in the wellbore. The wellbore is drilled with the use of a tool string consisting of drill pipe, various tools and having a drill bit on the distal end. During the drilling of the wellbore drilling fluid is typically circulated through the tool string and the drill bit and returns up the annulus between the tool string and the wellbore. After the wellbore is drilled typically the tool string is pulled out of the wellbore and a string of pipe, e.g., casing, can be run in the wellbore. The drilling fluid is then usually circulated downwardly through the interior of the pipe and upwardly through the annulus between the exterior of the pipe and the walls of the wellbore, although other methodologies are known in the art.

Slurries such as hydraulic cement compositions are commonly employed in the drilling, completion and repair of oil and gas wells. For example, hydraulic cement compositions are utilized in primary cementing operations whereby strings of pipe such as casing are cemented into wellbores. In performing primary cementing, a hydraulic cement composition is pumped into the annular space between the walls of a wellbore and the exterior surfaces of the casing. The cement composition is allowed to set in the annular space, thus forming an annular sheath of hardened substantially impermeable cement. This cement sheath physically supports and positions the casing relative to the walls of the wellbore and bonds the exterior surfaces of the casing string to the walls of the wellbore. The cement sheath prevents the unwanted migration of fluids between zones or formations penetrated by the wellbore.

The drilling of a horizontal well typically involves the drilling of an initial vertical well and then a lateral extending from the vertical well which arcs as it deviates away from vertical until it reaches a horizontal or near horizontal orientation into the subterranean formation.

In short radius drilling specialized tools are swept around a tight radius of a whipstock and are then used to form lateral boreholes radiating outward and into the subterranean formation. Short radius lateral drilling is distinct from more-familiar conventional horizontal and coil tubing drilling. In conventional horizontal and coil tubing drilling procedures, the drilling tools are swept around a radius or “heel” that is hundreds or even thousands of feet in size. That is, in both of these procedures virtually all of the change in direction takes place outside of the wellbore proper. By contrast, in short radius drilling, the primary change of direction occurs inside of the wellbore itself—that is, it occurs literally in the matter of a few inches.

As wellbores suited to this procedure commonly have a diameter of between about 4½″ to 7″, this equates to radii of between about 2¼″ to about 3½″ inches. In many short radius lateral drilling procedures a full 90 degree arc or “heel” is completed within the wellbore—that is, within about 0.25 ft (3 inches). This contrasts markedly with coiled tubing drilling, which often requires on the order of 250 feet and with conventional horizontal drilling which can utilize on the order of 2,500 feet for a full 90 degree heel. Conventional horizontal drilling technologies operate at a scale 3 to 4 orders of magnitude larger than those of short radius lateral drilling technologies.

The process of “radial drilling” entails forming extended boreholes (e.g. at least 5 feet) in earthen formations that extend outward from a primary wellbore. These laterals may extend as short as 5 feet or they may extend beyond 50 feet. In radial drilling, the exit angle from the primary wellbore ranges from 45 degrees to slightly over 90 degrees and form a “radial borehole”. As one might imagine, radial boreholes entail extraordinarily high “build-angles” for the tools. That is, these build-angles are diametrically opposed to those found in conventional rig-based or coiled tubing-based horizontal drilling procedures. In these arts, the tool-string exits the wellbore at extremely shallow exit angles, typically no more than 3 to 5 degrees.

In radial drilling the “heel” of the lateral sweeps out its arc in the matter of a few inches. In fact, typically the entire change of direction takes place inside of the wellbore itself. As typical wellbores range from about 4½ to 9 inches in diameter, the heel (or radius) in radial drilling procedures is literally inches. In more common coiled tubing drilling or conventional horizontal drilling, the heels are 100s or 1000s of feet in size. Basically, radial drilling procedures operate at a scale that is 3 to 4 order of magnitude less than industry-standard methods.

Radial drilling procedures typically entail the placement of a whipstock at a target depth inside the wellbore. Commonly, the whipstock has a sort of “J-path” that directs the small cutting tools around the tight radius. Sometimes the whipstock is run on the end of upset or production tubing. Radial drilling related tools and procedures can be used on open-hole completed or cased hole wells. If no opening is present in a cased well, access to the formation is sometimes gained by milling out a section of the metal well casing. More commonly, however, a specialized tool-string is moved down the wellbore and are used to form a small round hole in the casing, typically about ¾″ to 1½″ in diameter. In known practices, the tools used to form the hole in the casing are then retracted and a separate formation-drilling tool is inserted downhole.

The formation-drilling tools are then directed by the whipstock toward the earthen formation or target zone (through the existing hole in the casing). Obviously, in open-hole completed wells, there is no need to cut the casing. Regardless of whether the well is cased or open hole completed, the tools are manipulated by some form of control-line. The control-line might be a wireline unit, a coil tubing unit (CTU) or jointed-tubing.

Virtually all known, commercial radial-drilling technologies rely upon high pressure jetting nozzles in an attempt to erode a borehole in the rock. These systems, however, have proven unreliable, especially when cutting harder materials like dolomites, sandstones and high-compressive strength rock. A more promising solution entails using a mechanical drill bit. However, such systems suffer from several shortcomings.

The genesis of these shortcomings stems largely from difficulties unique to radial drilling. For example, in radial drilling procedures the radius in the whipstock can be 90 degrees. As in conventional drilling operations, the weight on bit (WOB) in radial drilling is derived from the weight of the tool-string above. Due to tight J-path in radial drilling, a portion of this weight is lost when transitioning the tools around the tight radius of the whipstock. That is, a portion of the drive force becomes “stacked out” in the whipstock. This causes a reduction in the available WOB and can result in slower rates of penetration (ROPs), especially when drilling consolidated rock formations. Another problem is encountered when drilling abrasive formations, such as sandstone, wherein the hard silica can quickly erode or dull conventional cutting-heads resulting in a low ROP or, in severe case, in no penetration whatsoever.

A new proposal involves using PDC (poly-diamond compact) inserts for radial drilling applications, but doing so presents some challenges. For example, PDC inserts are made from extremely specialized machinery, which is only known to produce the formation drilling inserts in circular “moon” or semi-circular “half-moon” profiles. Because PDCs are extraordinarily hard, conventional machining techniques, such as mechanical cutting or conventional grinding, are not practical for re-shaping those inserts to profiles better suited to cutting rock. This presents a problem in that the mechanical radial drilling bit designer is thus presently limited to only full or half-moon profiles when designing a cutting-head for this application.

In addition to the above “shape” limitations, there are severe “size” limitations. For example moon and half-moon PDC inserts for oil and gas drilling applications are only known to be available in certain sizes ranging from 6 mm to 19 mm in diameter. Moreover, in known PDC insert, the diamond compact thickness itself ranges from 2 mm to 4 mm. In addition to this diamond compact thickness, PDCs are manufactured with a “backer-material” which is necessary for affixing the insert to the cutting head and helps resist breakage during the high compressive loads experienced during drilling. This backer material is commonly 2 mm to over 6 mm in thickness, thus adding yet further to the overall thickness of the insert.

Moreover, when designing a drill-bit for radial drilling applications, besides the thickness of the PDC and its backer material, the designer must also consider placement of the insert on some form of rest or seat on the cutting head. This seat essentially serves two functions: 1) to provide a back support to help the insert resist the drive force (or weight on bit); and, 2) to provide back support to the rotational torque loads experienced during drilling. While the body of radial cutting heads and the seat themselves are made of steel or alloy, the back support must still be thick enough to resist breakage during operation. This is accomplished by making the back support relatively thick so as to distribute the applied load and remain below the metal's yield point. To adequately support operating loads in radial drilling applications, the back support thickness must be in the range of about 8 mm to 12 mm in thickness. Therefore, the overall space required for a typical cutting insert for radial drilling applications can quickly reach or exceed 12 mm to 16 mm (2 mm for PDC+2 mm for backer+8 to 12 mm for back-support).

Because of the extremely tight radius of the heel involved in radial-drilling applications, the cutting-head diameters are necessarily small, often on the scale of about 25 to 35 mm in diameter. Given these small diameters and corresponding small circumferences, the designer of a cutting head for radial drilling applications is severely limited both in terms of the number and placement of PDC inserts on the cutting head. This problem stems from the large ratio of the PDC insert's diameter to the cutting head overall diameter. For example, only two 13 mm wide inserts can be placed on a diameter/centerline of a 26 mm cutting head. At this point, the diameter is essentially full and more inserts cannot be placed on it. The solution would be to place more-but-smaller inserts on the cutting head but even this solution offers an unsatisfactory improvement. For example, a 6 mm diameter insert placed on a 24 mm diameter head allows only 4 inserts to be placed on the diameter. Because the length of the insert is 25% (6 mm vs. 24 mm) of the diameter of the cutting head, the available insert placement and design options are severely limited. Moreover, if one were thinking to place additional inserts on the cutting head but along a different diameter (e.g. at a different angle), they would be severely limited because of the overall space taken up by the thickness of the previous placed inserts, backer-material and back support.

The problem described above is very different from what designers and manufacturers of cutting heads used in conventional oil and gas drilling applications face. In these applications, the drill heads are far larger, more on the scale of 125 mm to over 250 mm in diameter. Thus, that same 6 mm or 19 mm PDC insert, discussed above, is but a small fraction of the diameter of the cutting head onto which it is placed. Take for example a 6 mm insert on a 180 mm cutting head. The 6 mm insert equates to only 1/30^(th) or a mere 3.3% of the cutting head diameter vs. the 25% it consumes on a 24 mm radial drilling head. In essence, the larger scale cutting heads of conventional oil and gas drilling make for a workable ratio of the size of the insert to the size of the cutting head. Because of this ratio, conventional oil and gas drilling bits can have dozens of inserts on them and the bit designer has wide freedom when it comes to cutting geometries and defining cutting profiles by the collective placement of numerous inserts.

This is not the case for radial drilling. The options available to the radial drilling bit designers are severely limited in terms of the number, placement and orientation of the inserts that can be placed on the much smaller cutting head. This sub-optimal reality can result in any or all of the following adverse consequences for radial drilling: (A) Cutting face geometries that render the drill bit incapable of applying sufficient force (point-loading) to fracture hard rocks. (B) ROPs that are unacceptably low due to the small size of the rock cuttings that are generated (e.g. polishing the rock vs. cutting the rock). (C) Extremely higher drive forces (weight on bit) requirements. (D) High tool wear and/or premature tool failure may occur.

A radial drilling bit designer wanting to use PDCs for inserts cannot cut or shape those inserts with convention machining tools. For example, one cannot cut the PDCs by mechanical cutting means as the cutting tools are softer than the material being cut. Since, however, there are few sizes and shapes (or profiles) of inserts available, the designer of radial drilling bits is severely limited on what kind of cutting geometries or cutting profiles they can design into the cutting head.

A further problem in radial drilling pertains to precisely placing the cutting inserts on the small cutting head. Often, the cutting head has a flat seat on which the insert is placed before it is brazed on the cutting head. When brazing the insert onto the cutting head, sometimes the insert moves slightly off-center. For example, the insert may inadvertently slide a mere 0.1 mm (or about 0.004″) out of location in the molten puddle. While only the thickness of a common sheet of paper, even this small distance can adversely affect drilling efficiency by introducing the problem of bit whirl.

Bit whirl induces several problems including: wearing the drill bit; poor hole quality; and reducing the cutting efficiency of the bit. This phenomenon affects large, conventional scale oil and gas drill bit but also smaller scale radial drilling. Indeed, the “small” error in placement can be all the more pronounced in radial drilling due to the small diameter of the cutting head.

In light of the above problems, a solution is needed that allow bit designers greater freedom to design and manufacture radial drilling cutting heads capable of cutting rock formations.

SUMMARY

This disclosure applies to radial drilling applications wherein lateral boreholes are mechanically drilled outward from an existing primary wellbore at between 45 to about 90 degrees. This disclosure overcomes current design and manufacturing limitations when creating drill heads used specifically in radial drilling applications. This invention encompasses “toothed” or “serrated” cutting edge profiles necessary for high point loading and rock fracturing of hard rocks. In embodiments, it does this by incorporating these features directly into the cutting edge of the individual inserts themselves rather than by collectively defining such profiles by the placement of multiple inserts. In addition, the cutting inserts can be precisely affixed by a “male” and “female” mating system involving the inserts and seats on the cutting-head.

BRIEF DESCRIPTION OF DRAWINGS

The accompanying views of the drawing are incorporated into and form a part of the specification to illustrate several aspects and examples of the present disclosure, wherein like reference numbers refer to like parts throughout the figures of the drawing. These figures together with the description serve to explain the general principles of the disclosure. The figures are only for the purpose of illustrating preferred and alternative examples of how the various aspects of the disclosure can be made and used and are not to be construed as limiting the disclosure to only the illustrated and described examples. The various advantages and features of the various aspects of the present disclosure will be apparent from a consideration of the figures.

FIGS. 1A and 1C illustrate “full-moon” and “half-moon” PDC inserts, while FIGS. 1B and 1D reflect these inserts in profile view, allowing a view of the backer material.

FIG. 2A illustrates a top view of a common 16 mm full-moon PDC insert positioned upon a 24 mm diameter cutting-head used for radial drilling, while FIG. 2B illustrates it in a profile view.

FIG. 3A illustrates a top view a 24 mm diameter cutting-head, similar to that in FIG. 2A, but with two 12 mm half-moon PDC insert positioned on the cutting-head. Also shown are the back-supports and two fluid exits ports.

FIG. 4A illustrates a half-moon PDC insert that has been cut vertically so as to fit on small cutting head, while FIGS. 4B and 4C illustrates profile view of insert 4A. FIG. 4D illustrates a PDC insert that has been cut vertically as in FIG. 4A, but its lower edge has also been cut at an angle.

FIG. 5A illustrates a top view of a cutting-head without inserts allowing one to fully see the three fluid exit ports, seats, and back-supports. FIG. 5B illustrates the same cutting-head as FIG. 5A but with the inserts placed on the head and partially obstructing the fluid ports. To present the cutting profile, FIG. 5C illustrates the cutting-head of FIG. 5B in a partial cross-sectional view (right-side) that has then been mirrored about the axis of rotation (left-side).

FIG. 6A illustrates a PDC insert that has been cut vertically and also has been notched to create a profiled cutting-edge. FIG. 6B illustrates the cutting insert in a profile view, with the notch shown unshaded, for clarity. FIG. 6C also illustrates the cutting insert of FIG. 6A but this time from the plan view. Again, the notch has been shown in white, for clarity. FIG. 6E illustrates a cutting insert with offset-notch designed to work in conjunction with the cutting insert of FIG. 6A; while FIG. 6F illustrates the cutting insert of FIG. 6A superimposed on the insert of FIG. 6E.

FIG. 7A illustrates a profile view of a carbide insert which has a profiled cutting edge, in this case a “serrated” edge. FIG. 7B illustrates a carbide insert with a similar, basic “triangular” geometry but with a set of “chip breakers” instead of the “serrations” of FIG. 7A. FIG. 7C illustrates an insert with another form of chip breakers, this time running the length of the cutting edges. FIG. 7D illustrates the profile view of the insert of FIG. 7C.

FIG. 8A illustrates a PDC insert that has been notched to allow for precise positioning into the mating protrusions on the seats of FIG. 8B. Two drilling-fluid exit ports are seen cutting through the seats. FIG. 8C is a cross-sectional side view of the cutting-head of FIG. 8B, shown are the backer-support, mating protrusion on the seat and inner fluid passageways. FIG. 8D illustrates the cutting head of FIG. 8B with two inserts placed on the seats and partially obstructing the two fluid exit ports.

FIG. 9A illustrates a cutting-head with a single fluid exit port positioned in the center of the cutting head and with grooves formed along the outside edge of the cutting-head to allow fluid to pass. The inserts have not yet been placed in the seats. FIG. 9B illustrates the cutting head of FIG. 9A with two triangular cutting inserts placed upon the seat and resting against the back-supports. A lower section of each insert is unsupported above the fluid exit port. FIG. 9C illustrates a cross-sectional side view of the cutting-head of FIG. 9B with one cutting insert visible atop the cutting head. Drilling fluid (shown by arrows) can be seen contacting to lower face of the insert as it exits the cutting head.

FIG. 10 illustrates a drilling head of this disclosure being used in a typical radial drilling application.

DETAILED DESCRIPTION

This disclosure entails drill bits with cutting face and edge geometries especially suited to radial-drilling applications. These profiles could not normally be attained in the requisite small sizes for radial drilling with conventional hard inserts, such as PDC, carbide, cubic boron nitride and similar hard insert materials used for rock drilling. This disclosure affords the radial drilling bit designer with the capability of designing and manufacturing complex cutting-edge profiles, including profiles that produce high point loading necessary to fracture harder rock.

The expanded angles and geometries of this disclosure stand in contrast to the limited circular and semi-circular profiles available in PDC inserts used in conventional oil and gas drilling applications. Embodiments of this disclosure entail profiles or interrupted cutting edges such as serrations, teeth and “chip breakers” that are emplaced along the cutting face edges of the insert. The purpose of these profiles are to better point load the rock so as to initiate fracturing and more efficiently generate rock cuttings. Again, the cutting edge of the individual inserts themselves have these geometric features rather than the formation of such profiles by the placement of multiple inserts on the cutting head, as is normally the case in oil and gas drilling.

In embodiments, the profile of the individual inserts placed on the drill head are designed so as to cut an area deliberately uncut by another insert of the drill head. For example, in at least one embodiment the cutting head is composed of three inserts that each have individual notches or teeth along the face of the insert. Because of its respective notch, when rotated, any one insert will fail to cut the full rock face. An adjacent insert, however, will have a tooth in just the right position (e.g. the corresponding radial location) to cut away the portion uncut by the prior insert. Thus, when rotated, what the notch on one insert fails to cut, the tooth on a subsequent insert cuts. In other embodiments shown in the figures, the individual inserts comprise serration and chip breaker features along the cutting edges.

By reducing the amount of cutting edge on each insert, one increases the point loading on the rock face and can thereby improve cuttings generation from the rock matrix. In normal “full-sized” oil and gas drill bits, this is of course also done. However, it is principally done by the spacing and arrangement of collective inserts rather than by features on the individual inserts themselves. Again, for radial drilling, this option is not a feasible solution because the small size of the drill heads.

Given the small diameter of the drill bits used in radial-drilling applications, micro-fractures and heterogeneities in the rock, which serve as natural fracture planes, can be exploited to help in chip generation. This mechanism can help improve the rate of penetration of a given drill bit while reducing the specific energy required to drill a given depth into the formation. In embodiments, the inserts are made with features known as chip breakers in the machining industry. That is, the insert is designed with small notches along their cutting edge and/or undercuts along the cutting face that initiate rolling and shearing of the rock matrix being cut. Chip break features facilitate the creation of distinct cuttings and thereby improve the cutting efficiency.

The cutting-heads also have one or more interior passageway(s) to deliver drilling fluid to wash away cuttings and cool the cutting inserts. In some embodiments, there is a single, centrally-located fluid passageway. In certain embodiments, the flow through the fluid passageway is divided into multiple flow streams by one or more cutting inserts. For example, two cutting inserts may converge toward the cutting head's axis of rotation and thus divide a single centrally located fluid stream into two or more flow streams. In certain embodiments, a portion of the fluid exiting the cutting head, contacts or is partially obstructed by a lower portion of one or more cutting inserts. That is, a portion of an insert is “in the way” of part of the fluid exiting the cutting head.

In some embodiments in order to facilitate the passage of the cutting fluid and entrained cuttings along the perimeter of the cutting head, there are longitudinal grooves or notches extending from near the cutting inserts to toward the back of the cutting head along the periphery of the cutting head.

Having discussed the design of the cutting inserts and the cutting-head, we now turn to the manufacture of these apparatuses. PDC and other hard inserts (like carbide, alumina oxide and CBN) are extremely difficult if not impossible to machine or mill using conventional tools. This problem is especially evident when trying to cut PDCs. Moreover, given the small size and complexity of the inserts described herein, a highly-accurate and repeatable system of manufacturing the cutting insert is needed. The method to form the profile on these inserts is an electric discharge machine (EDM) machine operated by computer numeric controls (CNC) as such machines can repeatedly produce very fine details even in PDCs.

In order to precisely place and secure the aforementioned hard inserts (whether PDC, carbide, variants or similar) onto the cutting-head body, embodiments entail placing a “knob” or “notch”, basically a mating male and female member, on the cutting head and inserts. The male knob or female notch on the cutting head would precisely line-up with and mate to a corresponding feature on the inserts, thereby assuring the precise positioning of the inserts on the cutting head. By using this mated landing approach, one can produce very tight placement accuracies of the inserts on the cutting head. The inserts can then be brazed or affixed to the cutting head.

We now turn to a detailed description of the drawings.

FIG. 1A illustrates a full-moon PDC insert (1) with a PDC material (4) shown in the front. FIG. 1B illustrates a profile view of the full-moon PDC insert (1) of FIG. 1A. A backer material (3) is located behind the PDC material (4).

FIG. 1C illustrates a half-moon PDC insert (2) with a PDC material (4) shown in front. FIG. 1D illustrates a profile view of the half-moon PDC insert (2) of FIG. 1C. The backer material (3) is located behind the PDC material (4).

FIG. 2A illustrates a common 16 mm full-moon PDC insert (1) with backer material (3) positioned upon a 24 mm cutting head (5). As is evident, the relatively large size PDC insert (1) does not allow for many additional inserts (not shown) to be placed on the cutting head (5). FIG. 2B illustrates a profile view of FIG. 2A showing the PDC material (4) of the relatively “large” PDC insert (1). Again, little space remains for the additional inserts (not shown) to be placed upon the cutting head (5).

FIG. 3A illustrates a 24 mm diameter cutting head (5) with back support material (13) and unobstructed fluid exit ports (7) and inserts (2) being evident. Drilling fluid (shown by arrows) exits the fluid exit ports (7) without contacting the lower edge (not visible) of the cutting inserts (2). One can see that the drill bit designer's options for how many and where to place the inserts (2), back-supports (13) and fluid exit ports (7) are severely limited due to size constraints.

FIG. 4A shows a “relatively larger” half-moon PDC insert (2 a) that would otherwise be too wide to fit onto a given cutting-head (not shown). To solve this problem, one side of the insert (2 a) has been cut (2 b). FIG. 4B shows the half-moon PDC insert (2 a) of FIG. 4A in profile with the line (2 c) demarking where the cut (2 b) has been made. In addition, one can see a back relief angle (9) has been made in the backer material (3) located behind the PDC material (4) to allow for efficient cutting. FIG. 4C shows a plan view of the half-moon PDC insert (2 a) of FIGS. 4A and 4B. Evident in this view is the angled relief cut (9) on the trailing edge of the insert (2 a) to allow for improved cutting. Also shown are the backer material (3) and the PDC material (4).

FIG. 4D illustrates a half-moon PDC insert (2 g) that has been cut (2 h) on its side that will be positioned toward the center of a cutting-head (as in FIG. 5B). Also the insert (2 g) has been cut at an angle along its base (2 i) to match the angle of a seat (11) like that depicted in FIG. 5C onto which the insert (2 g) will be placed.

FIG. 5A shows a cutting head (5) in plan view without any inserts emplaced. Evident are the seats (11) upon which the inserts (not shown) will rest. The back-supports (13) and fluid exit ports (7) are evident on the cutting-head (5). FIG. 5B shows the cutting head (5) of FIG. 5A but three inserts (2 g) comprised of a backer material (3) and PDC material (4) have been installed. Three inserts (2 g) have been placed upon the seats (11) and against the back-support (13). The three fluid exit ports (7) are partially obstructed but still allow for fluid to exit the cutting head (5). Part of the fluid exiting the cutting head (5), contacts a lower surface or face (not shown) of the inserts (2 g). Also denoted is line X, which is used in FIG. 5C. FIG. 5C is a hybrid view showing the upper half of the apparatus of FIG. 5B viewed along line X (at right); this view has then been mirrored about line Y in order to allow the reader to comprehend the full profile such a cutting head (5) forms when used in operation (i.e when rotated). A fluid passageway (7 b) runs through the cutting head (5) and allows the fluid to exit through the fluid exit ports (7). As seen the angled cut (2 i) allows the insert (2 g) to properly seat on the cutting head (5). Evident from FIG. 5A-5C is the fact that a portion of the drilling fluids (shown by arrows) contacts a lower portion of the cutting inserts (2 g) before fully exiting the cutting head (5).

FIG. 6A is a profile view of a half-moon PDC insert (28 a) that has been “notched” (15 a) to create a profile along the cutting edge (30 a). The reduced contact area of the cutting edge (30 a) caused by the notch (15 a) increases the point loading of the material being cut (not shown). FIG. 6B illustrates the insert (28 a) of FIG. 6A a profile view, with a notched (15 a) area (again shown in white for clarity). FIG. 6C illustrates FIGS. 6A and 6B in plan view with the notch (15 a) cut into the cutting edge (30 a) of the insert (28 a) and with an outer relief (29) cut in the backer-material (3).

FIG. 6E illustrates a second insert (28 b) with a notch (15 b) shown in white producing cutting profile (30 b). The insert (28 b) is designed for use on the same cutting-head (not shown) as the insert (28 a) of FIG. 6A. FIG. 6F illustrates the insert (28 b) of FIG. 6E but with the notch (15 a) of FIG. 6A superimposed upon the insert (28 b) to allow the reader to better understand the resultant cutting profile (30 c).

FIG. 7A illustrates a profile view of a carbide cutting insert (24) used for radial drilling that has been “serrated” (17) along its cutting edge (24 a). The serrations or “teeth” (17) reduce the contact area of the cutting edge (24 a) to cause higher point loading of the material being cut (not shown) thereby improving the drilling ROP. FIG. 7B illustrates a carbide insert (24) but with a set of “chip breakers” (19) that have essentially divided the cutting edge (24 a) into segments that more easily precipitate the formation of discrete cuttings (not shown). Also shown is a back relief (25) on the insert (24). In this case, the relief (25) is defined by a chamfer but it (25) could also be a radius. FIG. 7C illustrates a carbide insert (24) with an alternate chip breaker (19 b) whose shape is perhaps more evident in FIG. 7D. In this case, the material being cut (not shown) is “rolled” as it contacts the cutting edge (24 a) of the insert (24). FIG. 7D illustrates a profile view of the insert (24) of FIG. 7C with curved chip breaker (19 b) of FIG. 7C. As one can see the chip breaker (19 b) has a curved shape that would cause the material being cut (not shown) to “roll” apart when in contact with the cutting edge (24 a).

FIG. 8A illustrates a half-moon PDC insert (30) into which a “female” notch (21 a) has been made in order to allow for precise mating of the insert (30) on the cutting-head (5) of FIG. 8B. FIG. 8B illustrates a plan view of a cutting-head (5) with “male” member (22 a) positioned on a seat (11). Also evident are the fluid exit ports (7), back-supports (13) and line X. FIG. 8C illustrates FIG. 8B in profile cut along line X. Evident in this figure is a back support (13) and seat (11) and its male member (22 a) into which the female notch (21 a) of FIG. 8a will mate so as to precisely position the insert (30) upon the cutting head (5). Also shown is a fluid passageway (7 b) and fluid exit ports (7). In FIG. 8D the cutting inserts (30) have been placed upon the cutting head (5) in the seats (11) (no longer evident). Also depicted are the two fluid exit ports (7) that are now partially obstructed by the inserts (30).

FIG. 9a illustrates a cutting head (5) similar to that in FIG. 8B except with a single centrally-located fluid exit port (7 c) that would results in a single fluid flow path or flow stream (shown by straight arrow). In addition, groves (26) for the passage of cuttings can be seen extending along the periphery of the cutting head (5). Notably, the seats (11) do not block the central fluid exit port (7 c). FIG. 9B illustrates the cutting head (5) of FIG. 9A but with two triangular inserts (27) positioned on the cutting head (5). The triangular inserts (27) have been placed onto the seats (11) (no longer visible), and against the back supports (13). A portion of the inserts (27) covers part of the central fluid exit port (7 c) and is thus partially unsupported (as evident from FIG. 9A) by the seats (11). In addition, the placement of the inserts (27) onto the cutting head (5) has divided the formerly singular fluid flow stream (shown now by the two arrows). The grooves (26) positioned along the periphery of the cutting head (5) facilitate the efficient removal of cuttings (not shown) around the cutting head (5). FIG. 9C illustrates the cutting head (5) of FIG. 9B in profile along line X. Evident is the left triangular insert (27) with female notch (21) landed into the male member (22) of the cutting-head (5). The central fluid passageway (7 b) and cutting removal groves (26) are also evident. Some of the drilling fluid (shown by arrows) exiting the cutting-head (5), contacts a lower or bottom surface (31) of the insert (27).

FIG. 10 illustrates a control-line (40), in this case coil tubing (40) run by a coil tubing unit (43), being used to manipulate a radial drilling tool string (42) through a whipstock (44), which is run on the end of upset tubing (46) and secured by an anchor (48). The tool string (42) consists of a flexible drill string (50) with a mechanical cutting head (5); and, a downhole motor (52) controlled by coiled tubing (40). The mechanical cutting head (5) is cutting a deep lateral borehole (54) in the formation (59). Also shown is a wellhead (57) and a wellbore (58). However, for purposes of clarity, we have not shown arrows to depict the fluid flow.

An embodiment of the present disclosure is a cutting head apparatus for mechanical radial drilling includes one or more cutting inserts and at least one fluid passage way for the flow of drilling fluid through the cutting head. The cutting inserts can have a profiled cutting edge that point loads a rock being cut. The cutting inserts can be PDC inserts. Two or more cutting inserts can each have a different but complimentary cutting profile, the inserts positioned upon the cutting head to successively cut portions of a rock that are left uncut by another cutting insert. The drilling-fluid exiting the cutting head can contact a lower portion or face of the cutting inserts. The drilling-fluid can traverse through a centrally located orifice on the cutting head. The drilling-fluid can exit the cutting head and be split by the one or more cutting inserts. There can optionally be a groove that extends longitudinally along the cutting head to channel drilling fluid away from the cutting inserts. The one or more cutting inserts can have a bottom edge with a chamfer or optionally a radius. The at least one cutting insert can include a cutting edge with a chip breaker.

An alternate embodiment is a cutting-head apparatus for mechanical radial drilling that includes two or more cutting inserts having a profiled cutting edge that point loads a rock being cut. Each cutting insert having different but complimentary cutting profiles that are positioned upon the cutting-head to successively cut portions of the rock that are left uncut by another cutting insert. It further includes at least one fluid passage way for the flow of drilling fluid through the cutting head where the drilling-fluid exiting the drill head contacts a portion of the cutting inserts. The cutting inserts can be PDC cutting inserts. A drilling-fluid can traverse through a centrally located orifice on the cutting head, can exit the cutting head and be split by the one or more cutting inserts. The embodiment can further include a groove that extends longitudinally along the cutting head to channel drilling fluid away from the cutting inserts. The one or more cutting inserts can have a bottom edge with a chamfer or optionally a radius. The at least one cutting insert can include a cutting edge with a chip breaker.

An alternate embodiment is a method of manufacturing a profile on an insert used on a cutting head for radial drilling that includes electrical discharge machining the insert.

A further alternate embodiment is a method of placing a cutting insert on a cutting head used in radial drilling that includes locating an insert with a first shape that mates into a second shape in a seat on the cutting head.

The various embodiments of the present disclosure can be joined in combination with other embodiments of the disclosure and the listed embodiments herein are not meant to limit the disclosure. All combinations of various embodiments of the disclosure are enabled, even if not given in a particular example herein.

While illustrative embodiments have been depicted and described, modifications thereof can be made by one skilled in the art without departing from the scope of the disclosure. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents, the definitions that are consistent with this specification should be adopted. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Depending on the context, all references herein to the “disclosure” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present disclosure, which are included to enable a person of ordinary skill in the art to make and use the disclosures when the information in this patent is combined with available information and technology, the disclosures are not limited to only these particular embodiments, versions and examples.

Numerous other modifications, equivalents, and alternatives, will become apparent to those skilled in the art once the above disclosure is fully appreciated. While embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure.

Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable. Other and further embodiments, versions and examples of the disclosure may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow. 

1. A cutting-head apparatus for mechanical radial-drilling comprising: one or more cutting inserts; and at least one fluid passage way for the flow of drilling fluid through the cutting head.
 2. The apparatus of claim 1, further comprising the cutting inserts having a profiled cutting edge that point loads a rock being cut.
 3. The apparatus of claim 1, wherein the cutting inserts are PDC inserts.
 4. The apparatus of claim 1, further comprising two or more cutting inserts each having different but complimentary cutting profiles; said inserts positioned upon the cutting head to successively cut portions of a rock that are left uncut by another cutting insert.
 5. The apparatus of claim 1, wherein drilling-fluid exiting the cutting head contacts a lower portion of the cutting inserts.
 6. The apparatus of claim 1, wherein drilling-fluid traverses through a centrally located orifice on the cutting head.
 7. The apparatus of claim 1, wherein the drilling-fluid exits the cutting head and is split by the one or more cutting inserts.
 8. The apparatus of claim 1, further comprising a groove that extends longitudinally along the cutting head to channel drilling fluid away from the cutting inserts.
 9. The apparatus of claim 1, wherein one or more cutting inserts have a bottom edge with a chamfer.
 10. The apparatus of claim 1, wherein one or more cutting inserts have a bottom edge with a radius.
 11. The apparatus of claim 1, wherein at least one cutting insert comprises a cutting edge with a chip breaker.
 12. A cutting-head apparatus for mechanical radial drilling comprising: two or more cutting inserts having a profiled cutting edge that point-loads a rock being cut, each having different but complimentary cutting profiles, said inserts positioned upon the cutting head to successively cut portions of the rock that are left uncut by another cutting insert; at least one fluid passage-way for the flow of drilling fluid through the cutting head; wherein drilling-fluid exiting the cutting-head contacts a lower portion of the cutting inserts.
 13. The apparatus of claim 12, wherein the cutting inserts are PDC cutting inserts.
 14. The apparatus of claim 12, wherein drilling fluid traverses through a centrally located orifice on the cutting head.
 15. The apparatus of claim 12, wherein the drilling fluid exits the cutting head and is split by the one or more cutting inserts.
 16. The apparatus of claim 12, further comprising a groove that extends longitudinally along the cutting head to channel drilling fluid away from the cutting inserts.
 17. The apparatus of claim 12, wherein one or more cutting inserts have a bottom edge with a chamfer.
 18. The apparatus of claim 12, wherein at least one cutting insert comprises a cutting edge with a radius.
 19. The apparatus of claim 12, wherein at least one cutting insert comprises a cutting edge with a chip breaker.
 20. A method of manufacturing a profile on an insert used on a cutting head for radial drilling comprising electrical discharge machining the insert.
 21. A method of placing a cutting insert on a cutting head used in radial drilling comprising positioning an insert with a first shape that mates into a second shape in a seat on the cutting head. 